Methods and Apparatus for Downhole Extraction and Analysis of Heavy Oil

ABSTRACT

Methods and apparatus for downhole extraction and analysis of heavy oil are disclosed. An example method includes lowering a viscosity of formation fluid in a subterranean formation and flowing the formation fluid from the subterranean formation into a downhole tool. The example method also includes controlling the viscosity of at least a portion of the formation fluid in the downhole tool.

FIELD OF THE DISCLOSURE

This disclosure relates generally to sampling formation fluid and, moreparticularly, to methods and apparatus for downhole extraction andanalysis of heavy oil.

BACKGROUND

Recently, exploration of heavy oil has increased. Venezuela and Canadaeach have reserves of about 170 billion barrels of heavy oil. Theviscosity of the heavy oil is generally between 1,000 cP and 10,000 cP.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

An example method disclosed herein includes lowering a viscosity offormation fluid in a subterranean formation, flowing the formation fluidfrom the subterranean formation into a downhole tool, and controllingthe viscosity of a portion of the formation fluid in the downhole tool.

An example downhole tool disclosed herein includes a pressurizationdevice to draw formation fluid from a subterranean formation into aflowline of the example downhole tool. The example downhole tool alsoincludes a chamber to enclose a portion of the flowline. The chamber isto control a viscosity of the formation fluid flowing through theportion of the flowline enclosed by the chamber.

Another example method disclosed herein includes flowing formation fluidfrom a subterranean formation into a microfluidic flowline disposed in adownhole tool and controlling a viscosity of the formation fluid in aportion of the microfluidic flowline.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an example system in which embodiments of examplemethods and apparatus for downhole extraction and analysis of heavy oilcan be implemented.

FIG. 2 illustrates another example system in which embodiments of theexample methods and apparatus for downhole extraction and analysis ofheavy oil can be implemented.

FIG. 3 illustrates another example system in which embodiments of theexample methods and apparatus for downhole extraction and analysis ofheavy oil can be implemented.

FIG. 4 illustrates various components of an example device that canimplement embodiments of the methods and apparatus for downholeextraction and analysis of heavy oil.

FIG. 5 also illustrates various components of the example device thatcan implement embodiments of the methods and apparatus for downholeextraction and analysis of heavy oil.

FIG. 6 illustrates example methods for downhole extraction and analysisof heavy oil in accordance with one or more embodiments.

DETAILED DESCRIPTION

Certain examples are shown in the above-identified figures and describedin detail below. In describing these examples, like or identicalreference numbers are used to identify common or similar elements. Thefigures are not necessarily to scale and certain features and certainviews of the figures may be shown exaggerated in scale or in schematicfor clarity and/or conciseness. Accordingly, while the followingdescribes example systems, persons of ordinary skill in the art willreadily appreciate that the examples are not the only way to implementsuch systems.

Example methods and apparatus for downhole extraction and analysis ofheavy oil are disclosed herein. Example methods disclosed herein mayinclude lowering a viscosity of formation fluid in a subterraneanformation. Lowering the viscosity of the formation fluid in thesubterranean formation may include heating the subterranean formation.The example methods may also include flowing the formation fluid fromthe subterranean formation into a downhole tool and controlling theviscosity of at least a portion of the formation fluid in the downholetool. Flowing the formation fluid into the downhole tool may includecontrolling a pressurization device. The viscosity of at least a portionof the formation fluid in the downhole tool may be controlled byseparating a hydrocarbon phase from the formation fluid and heating thehydrocarbon phase. In some examples, the hydrocarbon phase is separatedfrom the formation fluid by flowing the formation fluid through ahydrophobic filter.

FIG. 1 illustrates a wellsite system in which the present invention canbe employed. The wellsite can be onshore or offshore. In this examplesystem, a borehole 11 is formed in subsurface formations by rotarydrilling in a manner that is well known. Embodiments can also usedirectional drilling, as will be described hereinafter.

A drill string 12 is suspended within the borehole 11 and has a bottomhole assembly 100 which includes a drill bit 105 at its lower end. Thesurface system includes platform and derrick assembly 10 positioned overthe borehole 11. The assembly 10 includes a rotary table 16, kelly 17,hook 18 and rotary swivel 19. The drill string 12 is rotated by therotary table 16, energized by means not shown, which engages the kelly17 at the upper end of the drill string 12. The drill string 12 issuspended from the hook 18, attached to a traveling block (also notshown), through the kelly 17 and the rotary swivel 19, which permitsrotation of the drill string 12 relative to the hook 18. As is wellknown, a top drive system could also be used.

In the example of this embodiment, the surface system further includesdrilling fluid or mud 26 stored in a pit 27 formed at the well site. Apump 29 delivers the drilling fluid 26 to the interior of the drillstring 12 via a port in the swivel 19, causing the drilling fluid 26 toflow downwardly through the drill string 12 as indicated by thedirectional arrow 8. The drilling fluid 26 exits the drill string 12 viaports in the drill bit 105, and then circulates upwardly through theannulus region between the outside of the drill string and the wall ofthe borehole, as indicated by the directional arrows 9. In this wellknown manner, the drilling fluid 26 lubricates the drill bit 105 andcarries formation cuttings up to the surface as it is returned to thepit 27 for recirculation.

The bottom hole assembly 100 of the illustrated embodiment including alogging-while-drilling (LWD) module 120, a measuring-while-drilling(MWD) module 130, a roto-steerable system and motor 150, and drill bit105.

The LWD module 120 is housed in a special type of drill collar, as isknown in the art, and can contain one or a plurality of known types oflogging tools. It will also be understood that more than one LWD and/orMWD module can be employed, e.g. as represented at 120A. (References,throughout, to a module at the position of 120 can also mean a module atthe position of 120A as well.) The LWD module 120 includes capabilitiesfor measuring, processing, and storing information, as well as forcommunicating with the surface equipment. In the present embodiment, theLWD module 120 includes a fluid sampling device.

The MWD module 130 is also housed in a special type of drill collar, asis known in the art, and can contain one or more devices for measuringcharacteristics of the drill string 12 and drill bit. The MWD toolfurther includes an apparatus (not shown) for generating electricalpower to the downhole system. This may include a mud turbine generatorpowered by the flow of the drilling fluid, it being understood thatother power and/or battery systems may be employed. In the presentembodiment, the MWD module 130 includes one or more of the followingtypes of measuring devices: a weight-on-bit measuring device, a torquemeasuring device, a vibration measuring device, a shock measuringdevice, a stick slip measuring device, a direction measuring device, andan inclination measuring device.

FIG. 2 is a simplified diagram of a sampling-while-drilling loggingdevice of a type described in U.S. Pat. No. 7,114,562, incorporatedherein by reference in its entirety, utilized as the LWD tool 120 orpart of an LWD tool suite 120A. The LWD tool 120 is provided with aprobe 6 for establishing fluid communication with a formation F anddrawing the fluid 21 into the tool, as indicated by the arrows. Theprobe 6 may be positioned in a stabilizer blade 23 of the LWD tool andextended therefrom to engage the borehole wall. The stabilizer blade 23comprises one or more blades that are in contact with the borehole wall.Fluid drawn into the downhole tool using the probe 6 may be measured todetermine, for example, pretest and/or pressure parameters.Additionally, the LWD tool 120 may be provided with devices, such assample chambers, for collecting fluid samples for retrieval at thesurface. Backup pistons 81 may also be provided to assist in applyingforce to push the drilling tool and/or probe against the borehole wall.

Referring to FIG. 3, shown is an example wireline tool 300 that may beanother environment in which aspects of the present disclosure may beimplemented. The example wireline tool 300 is suspended in a wellbore302 from the lower end of a multiconductor cable 304 that is spooled ona winch (not shown) at the Earth's surface. At the surface, the cable304 is communicatively coupled to an electronics and processing system306. The example wireline tool 300 includes an elongated body 308 thatincludes a formation tester 314 having a selectively extendable probeassembly 316 and a selectively extendable tool anchoring member 318 thatare arranged on opposite sides of the elongated body 308. Additionalcomponents (e.g., 310) may also be included in the tool 300.

The extendable probe assembly 316 may selectively seal off or isolateselected portions of the wall of the wellbore 302 to fluidly couple tothe adjacent formation F and/or to draw fluid samples from the formationF. Accordingly, the extendable probe assembly 316 may be provided with aprobe having an embedded plate, as described above. The formation fluidmay be expelled through a port (not shown) or it may be sent to one ormore fluid collecting chambers 320 and 322. In the illustrated example,the electronics and processing system 306 and/or a downhole controlsystem are configured to control the extendable probe assembly 316and/or the drawing of a fluid sample from the formation F.

FIG. 4 is a schematic view of an example downhole tool 400 that may beused to implement the example tools 100 and 120 of FIGS. 1 and 2 and 300of FIG. 3. The example downhole tool 400 includes an elongated body 402having an inlet 404 fluidly coupled to a main flowline 406. A separationblock 408 such as, for example, a separation block described in U.S.Pat. No. 7,575,681, entitled “Microfluidic Separator” and filed on Sep.8, 2004, which is incorporated herein by reference in its entirety, isadjacent the inlet 404 along the main flowline 406. The separation block408 includes a filter 410 (e.g., a polytetrafluoroethylene membrane). Insome examples, the filter 410 is hydrophobic and/or microfluidic. Amicrofluidic flowline 412 is fluidly coupled to the separation block408. The microfluidic flowline 412 passes through at least one sensor414, 416, 418, 420 and 422 (e.g., a viscometer, a bubble point sensor,etc.) disposed in a chamber 424. In some examples, one or more of thesensors 414, 416, 418, 420 and 422 are microfluidic. The chamber 424encloses a portion of the microfluidic flowline 412.

The chamber 424 includes a heater 426 (e.g., a resistor wire) to controla temperature of an interior of the chamber 424. In some examples, thechamber 424 includes a fan and/or pump to circulate air inside thechamber 424. The microfluidic flowline 412 extends through the chamber424 and is fluidly coupled to the main flowline 406 downstream of abackpressure regulator 428 such as, for example, a check valve or arelief valve disposed along the main flowline 406. A pressurizationdevice 430 disposed in the example downhole tool 400 is fluidly coupledto an outlet 432 of the main flow line 406. In the example illustratedin FIG. 4, the pressurization device 430 is a piston 434 disposed in acylinder 436. In some examples, the cylinder 436 has a volume of about 1L. In other examples, the pressurization device 430 is a pump. Theexample downhole tool 400 also includes backup pistons 438.

FIG. 5 is a simplified, front view of the example downhole tool 400 ofFIG. 4. The example downhole tool 400 includes a packer 500 adjacent theinlet 404 and a heater 502 adjacent the packer 500. The heater 502 is toheat a subterranean formation via conduction, ohmic heating, and/ormicrowave heating.

During operation, the heater 502 may be used to heat a subterraneanformation to lower a viscosity of the formation fluid in thesubterranean formation to a suitable viscosity (e.g., about 1000 cP). Insome examples, the heater 502 heats about 1 L to about 1.5 L offormation fluid in the subterranean formation. Once the viscosity of theformation fluid is lowered to the suitable viscosity, the pressurizationdevice 430 draws the formation fluid from the subterranean formationinto the main flowline 406 of the example downhole tool 400. In someexamples, the pressurization device 430 draws about 100 mL to about 0.5L of formation fluid into the main flowline 406. The pressurizationdevice 430, the backpressure regulator 428 and/or the filter 410disposed in the separation block 408 cause a pressure differentialacross the filter 410 and between the main flowline 406 and themicrofluidic flowline 412. As a result, the formation fluid passesthrough the filter 410, and a portion of the formation fluid (e.g., ahydrocarbon phase of the formation fluid) is separated from theformation fluid by the filter 410 and flows into the microfluidicflowline 412. A remainder of the formation fluid flows into the mainflowline 406 downstream of the separation block 408, and the separatedportion of the formation fluid (e.g., the hydrocarbon phase) is inducedto flow into the microfluidic flowline 412 by the pressure differential.

The separated portion of the formation fluid passes through the one ormore microfluidic sensors 414, 416, 418, 420 and 422 disposed in thechamber 424 to determine at least one characteristic (e.g., viscosity,density, composition, etc.) of the separated portion of the formationfluid. The heater 426 heats the interior of the chamber 424 to controlthe viscosity of the separated portion of the formation fluid flowingthrough the portion of the microfluidic flowline 412 enclosed by thechamber 424. After the separated portion of the formation fluid passesthrough the one or more microfluidic sensors 414, 416, 418, 420 and 422,the separated portion of the formation fluid flows into the mainflowline 406 downstream of the pressure regulator 428. The separatedportion and the remainder of the formation fluid are then drawn intocylinder 436 by the piston 434.

FIG. 6 depicts an example flow diagram representative of processes thatmay be implemented using, for example, computer readable instructions.The example process of FIG. 6 may be performed using a processor, acontroller and/or any other suitable processing device. For example, theexample processes of FIG. 6 may be implemented using coded instructions(e.g., computer readable instructions) stored on a tangible computerreadable medium such as a flash memory, a read-only memory (ROM), and/ora random-access memory (RAM). As used herein, the term tangible computerreadable medium is expressly defined to include any type of computerreadable storage and to exclude propagating signals. The example processof FIG. 6 may be implemented using coded instructions (e.g., computerreadable instructions) stored on a non-transitory computer readablemedium such as a flash memory, a read-only memory (ROM), a random-accessmemory (RAM), a cache, or any other storage media in which informationis stored for any duration (e.g., for extended time periods,permanently, brief instances, for temporarily buffering, and/or forcaching of the information). As used herein, the term non-transitorycomputer readable medium is expressly defined to include any type ofcomputer readable medium and to exclude propagating signals.

Some or all of the example process of FIG. 6 may be implemented usingany combination(s) of application specific integrated circuit(s)(ASIC(s)), programmable logic device(s) (PLD(s)), field programmablelogic device(s) (FPLD(s)), discrete logic, hardware, firmware, etc.Also, one or more operations depicted in FIG. 6 may be implementedmanually or as any combination(s) of any of the foregoing techniques,for example, any combination of firmware, software, discrete logicand/or hardware. Further, although the example process of FIG. 6 isdescribed with reference to the flow diagram of FIG. 6, other methods ofimplementing the process of FIG. 6 may be employed. For example, theorder of execution of the blocks may be changed, and/or some of theblocks described may be changed, eliminated, sub-divided, or combined.Additionally, one or more of the operations depicted in FIG. 6 may beperformed sequentially and/or in parallel by, for example, separateprocessing threads, processors, devices, discrete logic, circuits, etc.

FIG. 6 depicts an example process 600 that may be used with the exampledownhole tool 400 disclosed herein. The example process 600 begins bylowering a viscosity of the formation fluid in the subterraneanformation (block 602). The viscosity of the formation fluid may belowered by heating the subterranean formation. At block 604, it isdetermined if the viscosity of the formation fluid is less than about1000 cP. However, a different threshold viscosity value could be usedinstead. In some examples, whether the viscosity of the formation fluidis less than 1000 cP may be determined by an amount of time thesubterranean formation is heated (e.g., 45 minutes). If the viscosity ofthe formation fluid is not less than 1000 cP, then the example methodreturns to block 602. If the viscosity of the formation fluid is lessthan 1000 cP, then the formation fluid is flowed from the subterraneanformation into the example downhole tool 400 (block 606). In someexamples, the formation fluid is flowed into the main flowline 406 bycontrolling a pressurization device 430 such as the piston 434.

At block 608, a pressure differential is provided between the mainflowline 406 and the microfluidic flowline 412. In some examples, thepressurization device 430, the backpressure regulator 428 and/or thefilter 410 disposed in the separation block 408 provide the pressuredifferential across the filter 410 and between the main flowline 406 andthe microfluidic flowline 412. At block 610, a portion of the formationfluid is separated. For example, the pressure differential causes theformation fluid to pass through the filter 410 (e.g., a hydrophobicmembrane) in the separation block 408, and the filter 410 separates aportion of the formation fluid from a remainder of the formation fluid.In some examples, the portion of the formation fluid separated from theremainder of the formation fluid is a hydrocarbon phase. At block 612,the separated portion of the formation fluid is flowed into themicrofluidic flowline 412. For example, the differential pressureinduces the separated portion of the formation fluid to flow into themicrofluidic flowline 412.

A viscosity of the separated portion of the formation fluid is thencontrolled (block 614). The viscosity of the separated portion of theformation fluid may be controlled by controlling a temperature of theseparated portion of the formation fluid in the microfluidic flowline412. For example, the heater 426 of the chamber 424 heats the separatedportion of the formation fluid flowing through the microfluidic flowline412 enclosed by the chamber 424. At block 616, the separated portion ofthe formation fluid is flowed through at least one microfluidic sensor414, 416, 418, 420 and 422 (e.g., a viscometer, a bubble point sensor,etc.). At least one characteristic of the separated portion of theformation fluid is determined by the one or more sensors 414, 416, 418,420 and 422 (block 618).

Although a few example embodiments have been described in detail above,those skilled in the art will readily appreciate that many modificationsare possible in the example embodiments without materially departingfrom this invention. Accordingly, all such modifications are intended tobe included within the scope of this disclosure as defined in thefollowing claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function, structural equivalents, and also equivalentstructures. Thus, although a nail and a screw may not be structuralequivalents in that a nail employs a cylindrical surface to securewooden parts together, whereas a screw employs a helical surface, in theenvironment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of theclaims herein, except for those in which the claim expressly uses thewords ‘means for’ together with an associated function.

The Abstract at the end of this disclosure is provided to comply with 37C.F.R. § 1.72(b) to allow the reader to quickly ascertain the nature ofthe technical disclosure. It is submitted with the understanding that itwill not be used to interpret or limit the scope or meaning of theclaims.

What is claimed is:
 1. A method, comprising: lowering a viscosity offormation fluid in a subterranean formation; flowing the formation fluidfrom the subterranean formation into a downhole tool; and controllingthe viscosity of at least a portion of the formation fluid in thedownhole tool.
 2. The method of claim 1 wherein controlling theviscosity of at least a portion of the formation fluid in the downholetool comprises: separating a hydrocarbon phase from the formation fluid;and heating the hydrocarbon phase.
 3. The method of claim 2 whereinseparating the hydrocarbon phase from the formation fluid comprisesflowing the formation fluid through a hydrophobic filter.
 4. The methodof claim 2 further comprising providing a pressure differential toinduce the hydrocarbon phase to flow into a microfluidic flowline. 5.The method of claim 1 wherein controlling the viscosity of at least aportion of the formation fluid in the downhole tool comprisescontrolling a temperature of at least a portion of the formation fluidin the downhole tool.
 6. The method of claim 1 wherein lowering aviscosity of the formation fluid in the subterranean formation comprisesheating the subterranean formation.
 7. The method of claim 1 whereinflowing the formation fluid comprises controlling a pressurizationdevice.
 8. A downhole tool, comprising: a pressurization device to drawformation fluid from a subterranean formation into a flowline of thedownhole tool; and a chamber to enclose at least a portion of theflowline and control a viscosity of the formation fluid flowing throughthe portion of the flowline enclosed by the chamber.
 9. The downholetool of claim 8 further comprising a heater to heat the subterraneanformation.
 10. The downhole tool of claim 8 wherein the chambercomprises a heater to heat an interior of the chamber.
 11. The downholetool of claim 8 further comprising a hydrophobic filter to separate ahydrocarbon phase from the formation fluid, wherein the hydrocarbonphase is to flow through the portion of the flowline enclosed by thechamber.
 12. The downhole tool of claim 8 wherein the portion of theflowline enclosed by the chamber is a microfluidic.
 13. The downholetool of claim 8 wherein the pressurization device is a piston.
 14. Thedownhole tool of claim 8 further comprising at least one microfluidicsensor disposed in the chamber to determine a characteristic of thehydrocarbon phase.
 15. A method, comprising: flowing formation fluidfrom a subterranean formation into a microfluidic flowline disposed in adownhole tool; and controlling a viscosity of the formation fluid in atleast a portion of the microfluidic flowline.
 16. The method of claim 15further comprising heating the subterranean formation.
 17. The method ofclaim 15 wherein controlling a viscosity of the formation fluid in atleast a portion of the microfluidic flowline comprises controlling atemperature of at least a portion of the formation fluid in themicrofluidic flowline.
 18. The method of claim 15 wherein flowingformation fluid from the subterranean formation into the microfluidicflowline comprises: flowing formation fluid from the subterraneanformation into a main flowline; and providing a pressure differentialbetween the main flowline and the microfluidic flowline.
 19. The methodof claim 15 wherein flowing the formation fluid from the subterraneanformation into a microfluidic flowline comprises controlling apressurization device.
 20. The method of claim 15 further comprisingseparating a hydrocarbon phase from the formation fluid.